TC Energy Corporation (TRP) Q1 2021 Earnings Report, Transcript and Summary

Thank you for standing by. This is the conference operator. Welcome to the TC Energy First Quarter 2021 Results Conference Call. [Operator Instructions] I would now like to turn the conference over to David Moneta, Vice President, Investor Relations. Please go ahead.

Thanks very much and good afternoon everyone. I would like to welcome you to TC Energy’s 2021 first quarter conference call. Joining me today are Francois Poirier, President and Chief Executive Officer; Don Marchand, Executive Vice President, Strategy and Corporate Development and Chief Financial Officer; Tracy Robinson, President of our Canadian Natural Gas Pipelines and Coastal GasLink; Stan Chapman, President, U.S. and Mexico Natural Gas Pipelines; Bevin Wirzba, President, Liquids Pipelines; Corey Hessen, President, Power and Storage; and Glenn Menuz, Vice President and Controller. Francois and Don will begin today with some opening comments on our financial results and certain other company developments. A copy of the slide presentation that will accompany their remarks is available on our website. It can be found in the Investors section under the heading Events and Presentations. Following their prepared remarks, we will take questions from the investment community. If you are a member of the media, please contact Jaimie Harding following this call and she would be happy to address your questions. In order to provide everyone from the investment community with an equal opportunity to participate, we ask that you limit yourself to two questions. If you have additional questions, please re-enter the queue. Before Francois begins, I’d like to remind you that our remarks today will include forward-looking statements that are subject to important risks and uncertainties. For more information on these risks and uncertainties, please see the reports filed by TC Energy with Canadian securities regulators and with the U.S. Securities and Exchange Commission. And finally, during this presentation, we’ll refer to measures such as comparable earnings, comparable earnings per share, comparable EBITDA and comparable funds generated from operations. These and certain other measures are considered to be non-GAAP measures. As a result, they may not be comparable to similar measures presented by other entities. They are used to provide you with additional information on TC Energy’s operating performance, liquidity, and its ability to generate funds to finance its operations. With that, I will turn the call over to Francois.

Good afternoon, everyone and thank you for joining us this afternoon. As outlined in our first quarter report to shareholders, our diversified portfolio of high-quality, long-life energy infrastructure assets continued to perform very well in early 2021. Despite energy market volatility, weather events and the ongoing impacts of COVID-19, flows and utilization levels across our network remained strong. For example, our U.S. natural gas pipeline network moved nearly 29 Bcf per day in the first quarter, an increase of 4% over the same period in 2020, while field receipts on the NGTL System in Alberta were more than 12 Bcf per day. And in our Power and Storage business, Bruce Power continued to produce solid operating results, while in Alberta, output from our cogeneration plants nearly doubled due to the return to service – sorry, of our MacKay River plant and withdrawals from our natural gas storage facilities increased by 75% over the same period last year. Once again, this highlights the essential role our infrastructure plays in the functioning of the North American economy and the well-being of people across the continent. And we take this responsibility seriously. And as always, we conducted our business in a safe and reliable manner. Safety is one of our core values and is embedded in the fabric of our organization and evident in our commitment to ongoing pipeline system integrity. We’ve invested $150 million in pipeline inspection research and development since 2010 and billions in pipeline system integrity using the most sophisticated and advanced data analytics and risk evaluation methodologies in the industry. Our strong operating performance is also reflected in our solid financial performance with comparable EBITDA, comparable earnings per share and comparable funds generated from operations in the first quarter of 2021, all similar to last year’s record results. And this was achieved despite onetime Sur de Texas fees in the first quarter of 2020, the sale of our Ontario gas-fired generation assets last April and the loss of interest during construction on Keystone XL. Now on Keystone, we were very disappointed with the decision in January to revoke the presidential permit. As a result of the decision, we subsequently agreed with our partner, the government of Alberta, to formally suspend the project and evaluated our investment for impairment along with certain other projects in development, including the Heartland pipeline, TC terminals and the Keystone Hardisty terminal. This resulted in an after-tax asset impairment charge of $2.2 billion, which was excluded from comparable earnings. These costs will be shared with our partner, thereby reducing our net financial exposure at March 31 to approximately $1 billion. I would like to thank our customers, American and Canadian workers, our partners, the government of Alberta and Natural Law Energy, local communities, the pipeline building trade unions, industry, the government of Canada and countless others who supported this project over the past decade and would have shared greatly in its benefits. And while we are all disappointed with the outcome, the experience we gained is not lost. Through the process, we identified meaningful indigenous equity opportunities, collaborated with Union Labor and developed a robust plan to ensure the pipeline achieved net zero emissions from the moment it would have gone into service in 2023. And you can expect to see us continue to apply this innovative approach to projects in the future. Looking forward, we expect our solid operating and financial performance to continue, with 2021 comparable earnings per common share anticipated to be generally consistent with the record results we produced in 2020. We also continue to advance $20 billion of secured projects that are expected to enter service by 2024 and help power the North American economy for decades to come. A substantial portion of this growth is related to our natural gas pipeline network. This infrastructure is critical to support the transition to a lower carbon world as natural gas will play a key role in both displacing higher emission coal-fired power and providing the necessary backstop to the intermittency of renewable power. All of our projects are underpinned by cost of service regulation or long-term contracts, giving us visibility to the earnings and cash flow they will generate. In addition, we are progressing $7 billion of projects under development, including the refurbishment of another 5 reactors at Bruce Power. The refurbishment program will run through 2032 and is underpinned by a long-term contract with the Ontario ISO that extends to 2064, providing us with stable and predictable earnings and cash flow and the province with emissionless power. Over the mid to longer term, we expect numerous other opportunities to come to fruition as the world both consumes more energy and it transitions to a lower carbon energy future. Ultimately, our goal is to continue to invest $5 billion to $6 billion annually to deliver on our long-term growth plans. As you can see on this slide, our starting point is our $20 billion secured capital program. Beyond that, we expect to continue to invest $1.5 billion to $2 billion annually in maintenance and modernization programs across our extensive pipeline network, approximately 85% of which is recoverable through our rate-regulated businesses. We are also developing a significant suite of future growth opportunities. With the ongoing energy transition discussion, it’s easy to forget that the world will continue to rely on large quantities of natural gas and oil for the foreseeable future. And with 94,000 kilometers or 58,000 miles of existing natural gas pipelines, we are well positioned to continue to meet growing demand through highly executable in-corridor expansions. That said, the energy mix of the future will evolve with renewables, for example, making up a greater portion of the overall fuel mix. Our goal is to build on our long history of success and be agnostic to which form of energy will ultimately lead to a lower carbon energy future. As a result, you will see our capital allocation shift over time to meet the energy mix of the future, and to me, this is very exciting and represents a tremendous opportunity. Whether its renewables and the firming resources needed to manage their intermittency, electrifying our fleet or other emerging technologies, our existing asset base, technical capabilities, innovative approach and financial strength means that we are well positioned to prosper irrespective of the pace or direction energy transition takes. For example, we have been engaging with various stakeholders in Ontario to advance a large pump storage opportunity. The project is designed to store emission-free electricity and provide a backstop to the intermittency associated with the energy provided by renewables. More recently, through the issuance of a request for information, we’ve announced that we are seeking to identify potential contract and/or investment opportunities in wind energy projects that could generate up to 620 megawatts of zero-carbon energy to meet the electricity needs for a portion of our U.S. pipeline assets. This is an important step in advancing our plans to leverage the power business as a platform for future growth and diversification, while lowering emissions across our North American footprint. In summary, I believe we will be opportunity rich, and our challenge will be to allocate capital to those projects that are best aligned with our capabilities, our risk preferences and our return requirements. I can assure you we will not compromise our commitment to being thoughtful, deliberate and disciplined in every investment decision we make. Based on the continued strong performance of our base business and our organic growth plans, we expect to continue to grow our dividend at an average annual rate of 5% to 7%. As always, the growth in dividends is expected to be supported by sustainable growth in earnings and cash flow per share and strong coverage ratios. I’m confident that the future opportunity set, combined with our capabilities, will continue to deliver superior risk-adjusted total shareholder returns well into the future. I will now pass the call over to Don Marchand, who will provide more details on our first quarter financial results. Don?

Thanks, Francois, and good afternoon, everyone. As outlined in our results issued earlier today, we reported a net loss attributable to common shares for the first quarter of $1.1 billion or $1.11 per share as compared to net income of $1.1 billion or $1.22 per share for the same period in 2020. As Francois mentioned, the loss primarily stems from an after-tax asset impairment charge of $2.2 billion, related to the formal suspension of the Keystone XL pipeline project following the January 2021 revocation of the U.S. presidential permit. The charge is net of expected contractual recoveries and other contractual and legal obligations associated with suspension activities. However, it does not reflect offsetting amounts with respect to the Government of Alberta’s investment and guarantees which are expected to be recognized through the consolidated statement of equity in future periods. As at March 31, those include a contribution of $394 million for Class A interests reported in redeemable noncontrolling interest and $779 million outstanding on the guaranteed credit facility reported in the current portion of long-term debt. After taking these offsets into consideration, our net financial exposure on Keystone XL is approximately $1 billion. First quarter 2020 also included certain specific items outlined on the slide and discussed further in our first quarter 2021 report. These specific items as well as unrealized gains and losses from changes in risk management activities are excluded from comparable earnings. Comparable earnings in the first quarter were $1.1 billion or $1.16 per share and generally consistent with the $1.1 billion or $1.18 per share in 2020. Turning to our business segment results on Slide 11. In the first quarter, comparable EBITDA from our 5 operating segments of $2.5 billion was essentially in line with 2020. Canadian gas comparable EBITDA of $686 million was $89 million higher than the same period last year, primarily on account of increased flow-through depreciation and financial charges along with higher rate base earnings on the NGTL System, Coastal GasLink development fee revenue recognized in 2021 and higher flow-through income taxes on the Canadian Mainline. This was partially offset by lower flow-through income taxes on the NGTL System and financial charges on the Canadian Mainline. NGTL System net income increased $17 million compared to first quarter 2020 as a result of a higher average investment base from continued system expansions and reflects an ROE of 10.1% on 40% deemed common equity. Net income for the Canadian Mainline increased $12 million year-over-year, largely due to the elimination of a $20 million after-tax annual TC Energy contribution under the Mainline 2021-2026 settlement and higher incentive earnings in 2021. U.S. natural gas comparable EBITDA of $833 million or CAD1.1 billion in the quarter rose by $67 million or CAD23 million compared to the same period – same period last year. The improvement was due to increased earnings from Columbia Gas following the application for higher transportation rates effective February 1, subject to refund upon completion of its rate proceeding, along with incremental earnings resulting in a greater capitalized pipeline integrity costs in 2021 compared to 2020 and the contribution from growth projects placed in service, partially offset by higher property taxes associated with new projects. In addition, earnings across our U.S. gas pipeline assets were generally higher due to the cold weather events in first quarter 2021, which had an impact on many of the markets we serve. Mexico gas pipelines comparable EBITDA of $142 million or CAD180 million was $56 million or CAD89 million below first quarter 2020, largely due to a $55 million fees recognized in 2020 associated with the successful completion of the Sur de Texas pipeline. Liquids Pipelines comparable EBITDA declined by $52 million to $393 million in first quarter 2021, primarily due to the net effect of lower volumes on the Keystone Pipeline System and an increased contribution from liquids marketing activities mainly attributable to higher margins and volumes. Power and Storage comparable EBITDA fell by $13 million year-over-year to $181 million on account of decreased Bruce Power results, mainly attributable to the net effect of lower volumes resulting from greater outage days, partially offset by first quarter 2021 gains on funds invested for post-retirement benefits. For all our businesses with U.S. dollar-denominated income, including U.S. natural gas, Mexico gas pipelines and parts of Liquids Pipelines, translation of results into Canadian dollars occurred at an average exchange rate of $1.27 in first quarter ‘21 compared to $1.34 in 2020. While the weakening of the U.S. dollar had a negative impact on comparable EBITDA year-over-year, the corresponding effect on comparable earnings was not significant due to offsetting natural and economic hedges. To recap our approach to managing foreign exchange exposure, our U.S. dollar-denominated EBITDA streams are partially hedged by U.S. dollar-denominated interest, depreciation and taxes. We then actively manage the residual exposure on a rolling 2-year forward basis with realized gains and losses on this program reflected in comparable interest income and other. Now turning to the other income statement items on Slide 12, depreciation and amortization of $645 million increased $15 million versus first quarter 2020, largely due to new projects placed in service in Canadian and U.S. Natural Gas Pipelines. As a reminder, depreciation in Canada gas regulated pipelines is fully recoverable in tolls on a flow-through basis. Interest expense of $570 million for first quarter 2021 was $8 million lower year-over-year, due to the net effect of a weaker U.S. dollar on translation of U.S. dollar-denominated interest, long-term debt issuances net of maturities, lower interest rates on reduced levels of short-term borrowings and lower capitalized interest due to the completion of Napanee in first quarter 2020, the change to equity accounting for our Coastal GasLink investment in second quarter 2020 and the replication of the U.S. Presidential Permit to the Keystone XL pipeline in January 2021. AFUDC decreased $32 million compared to the same period in 2020, largely due to NGTL expansion projects placed in service and the suspension of recording AFUDC on Villa de Reyes effective January 1 due to ongoing delays on the project. Comparable interest income and other increased by $44 million in the first quarter versus 2020, primarily due to realized gains in 2021 compared to realized losses in 2020 on derivatives used to manage our structurally long exposure to U.S. dollar-denominated income, partially offset by lower unrealized foreign exchange gains on peso-denominated deferred income tax liabilities, net of derivatives used to manage this exposure. Income tax expense included in comparable earnings was $204 million in first quarter 2021, compared to $211 million for the same period last year, with the decrease mainly due to higher foreign tax rate differentials. Excluding Canadian rate-regulated pipelines where income taxes are a flow-through item and that’s quite variable along with equity AFUDC income in U.S. natural gas pipelines, we continue to expect our 2021 full year effective tax rate to be in the mid to high teens. Comparable net income attributable to non-controlling interest of $69 million in the first quarter decreased by $27 million relative to the same period last year, primarily due to the March 3, 2021, acquisition of all outstanding publicly held common units of TC PipeLines LP, which resulted in becoming an indirect wholly owned subsidiary of TC Energy. And finally, preferred share dividends were comparable to first quarter 2020. Now turning to Slide 13, during the first quarter, we invested approximately $1.9 billion, mainly towards expansion of the NGTL system, Columbia Gas projects as well as maintenance capital. As previously mentioned, in March, we completed the TC PipeLines LP acquisition in exchange for 38 million TC Energy common shares valued at approximately $2.1 billion. As the Pipe LP was previously fully consolidated in our accounts, the transaction was largely recorded within the equity component of our balance sheet. Additionally, in March, we issued $500 million of junior subordinated notes at a rate of 4.2% with the intent to redeem at par all $500 million of issued and outstanding Series 13 preferred shares on May 31. Finally, the fully guaranteed Keystone XL non-recourse project level credit facility current remains in place and is expected to fund the majority of residual costs. Now turning to Slide 14, this graphic highlights our forecasted sources and uses of funds for 2021 through 2023. Starting in the left column, the total funding requirement over the 3 years is projected to be approximately $29 billion, comprised of dividends of $11 billion, capital expenditures, including maintenance capital of $15.5 billion, $2 billion attributed to the TC PipeLines LP acquisition completed in March and $500 million related to the pending Series 13 preferred share redemptions. The second column highlights expected internally generated cash flow of $21 billion, $2 billion of common shares issued pursuant to the Pipe LP buy-in and the $500 million junior subordinated notes offering completed in March. That leaves a residual need of approximately $5.5 billion depicted in the far right column that will be funded predominantly through a combination of incremental debt, commercial paper and Keystone XL project recoveries. The program is consistent with our goal of maintaining debt to EBITDA in the high-4s and FFO to debt of 15%. Now turning to Slide 15, in closing, I will offer the following comments. Our solid financial and operational results in the first quarter continue to highlight our diversified low-risk business strategy and reflect the robust performance of our blue chip legacy portfolio, along with the contribution of equally high quality assets from our ongoing capital program. While we were very disappointed by the revocation of the Presidential Permit for Keystone XL and the resulting after-tax impairment charge, our irreplaceable footprint, proven organizational capabilities and vast opportunities that position us to continue to grow earnings and cash flow in the years ahead in accordance with our long standing risk preferences. This was expected to support annual dividend growth of 5% to 7% in the future. Our financial position remains strong with the ability to fund our $20 billion secured capital program through resilient and growing internally generated cash flow and an array of attractive capital sources. Finally, we will continue to maintain financial strength and flexibility at all points of the economic cycle. That’s the end of my prepared remarks. I will now turn the call back over to David for the Q&A.

Thanks, Don. Just a reminder, before I turn it back over to the conference coordinator for questions from the investment community, we ask that you limit yourself to two questions. If you have additional questions, please reenter the queue. With that, I will turn it over to the conference coordinator.

Thank you. We will now begin the question-and-answer session. [Operator Instructions] Our first question comes from Linda Ezergailis of TD Securities. Please go ahead.

Thank you. I am wondering if you can just elaborate a little bit more on your Slide 7 and what looks like your vision for the energy evolution that you will be participating in? And specifically, here, it talks about new investments, but it does seem that some of your existing assets might be used differently, including how your pipes might be contracted by your various customers, whether it would be LNG export or utilities or producers? How might this change the attributes of your cash flows, your risk profile, etcetera, and also potentially create service opportunities, for example, delivering – sourcing and delivering renewable natural gas increasingly as market needs evolve?

Hi Linda, it’s Francois. That’s a great question. I will get started, and I will ask Stan and then Tracy to offer some color and some proof points on each of Canada and the U.S. First, I will start with our overall philosophy is that we expect to continue to find plenty of opportunities to allocate our capital, either underpinned by regulation or long-term contracts. So, our approach with respect to what we are looking for, for our commercial sanctioning, will continue to be consistent with the way we have allocated capital in the past. It’s absolutely accurate that there are some opportunities to electrify and reduce emissions on our existing fleet, firstly. And then secondly, opportunities to invest in new technologies like hydrogen CCUS and transportation of renewable natural gas. So with that overarching comment, I will ask Stan to start and then move to Tracy.

Hi Linda, this is Stan. And maybe just to give you some potential of the perspective around your question about, 25% almost of our compression fleet is made up of slow-speed units and they range and age anywhere between 40 years to 70 years old. So electrifying these units, for example, would reduce our Scope 1 emissions by over 1 million tons. And you can think of that as about a 15% reduction of our overall emissions. And then we are going to work closely with Corey’s team, obviously, to find a green power solution to address the Scope 2 emissions. With your other question – other part of your question around who is likely to make up our pipeline holders going forward, today, when we look at our profile, we have about 40% LDC customers, a little less than 40% producer customers, and about 25% marketers or others. I think that’s a pretty well-rounded mix, and I really don’t see that changing that much into the future.

And Linda, I will come over talk to the Canadian systems. It’s a little bit different perspective. We are looking at the concept of the federal carbon tax and that growing over time provides a bit of a framework for how we think about it. At the first stage the emissions reductions, we have about just over 10% of our compression right now that’s electric. And as we look at the opportunity on that, we have identified kind of the next level of compressors that would be priority candidates based on utilization, size, age and proximity power. So, the next 30% to 40% of our compression is all good candidates, and we have got a subset of that, that they are working on most closely. You think about the emerging carbon tax. It makes it – gives us an opportunity to do that in a manner that offsets those taxes and the impact of tolls on our customers. So, that’s kind of first level for that, badness of methane reduction. So beyond that, there is waste heat opportunities taking that waste heat off our compression and providing it for power uses. And beyond that, we are sitting on top of the NGTL System, sitting on top of the WCSB positions us perfectly for the emerging mark that’s coming in hydrogen and hydrogen blending. We do see our pipes being big assets when it comes to thinking about the future of how hydrogen is going to move. I will leave it there for now.

Thank you. And as a follow-up, recognizing that there is a lot of organic growth and capabilities to capture that in your existing footprint, I am wondering if there might be an opportunity around the edges to accelerate your energy transition evolution by considering either acquisitions, divestitures, repurposing. I think you alluded to, especially on the hydrogen front, but also potentially some late-stage development opportunities, maybe some capabilities to round out what you already have in-house, etcetera. How are you thinking about that as being a lever to accelerate your transformation?

Linda, it’s Francois. Perhaps I will ask Corey to comment. As a proof point or an example, the RFI we issued to developers of wind assets for about 620 megawatts of load. And then perhaps I will ask Don to just comment generally on our efforts on the M&A side. So, Corey?

Hi, Linda. Yes, we recently went to market with an RFP for – an RFI, excuse me, for 620 megawatts of renewable wind energy to power pipe system in part of our North American footprint. We will be continuing that process with an additional RFI later on in May for solar energy as well. So, we see that as a very interesting opportunity set to leverage our existing load and bring economic opportunity to the company that aligns with our risk and return profile. I will pass it over to Don.

Hi, Linda. On the M&A front, we don’t – we don’t see M&A as necessary to meet our growth targets. But that said, we are always assessing the market and we are looking for opportunities to fill in gaps in the portfolio, consolidated ownership, improved connectivity and add capabilities, which I think is what you are alluding to here. If we look at where we might want to add capabilities, it would still fall into the more of the same category in terms of our risk preferences, what we are looking for to contribute to our return profiles, credit profiles, no fundamental change in geographies, basically long-term annuity stream. So, we are not looking to move up the risk curve. If we do look at new capabilities, we are not particularly interested in highly speculative technologies and the like on any large scale. So more of the same, but would help us progress things like the RFI, things that – where the puck is going, to look at a Gretzky quote, in terms of new technologies and new businesses.

Thank you. I will jump back in the queue.

Our next question comes from Robert Catellier of CIBC Capital Markets. Please go ahead.

Hi. Just a follow-up to that line of question, I am just curious what you think is necessary in terms of policy support. Obviously, the tax credits are something that’s being looked at. But in order to really – for the industry to get traction, both on CCUS-type investments, but also separately, if you could address that same question with respect to pump storage?

Perhaps I will get started, Rob, and I will ask – on the pump storage, I will ask Corey to backfill. First of all, we feel that the proposed tax incentives in the recent Canadian budget are a positive step, a step in the right direction, to have government and the private sector collaborate. We need those tax incentives to accelerate the development of the CCUS technology and develop it at scale. We also see opportunity for direct investment from the government through their accelerator fund as a big positive as well. So, those types of tax incentives that don’t pick winners and losers and create incentive for the private sector to innovate, we view that as one key requirement. The second is that the regulatory construct in our various jurisdictions follows the policy trends and again provide very clear rules for us to follow to be able to invest in the types of equipment and technologies that reduce emissions such that we can put them in a rate base and earn a return on and of capital, of course, to the extent that it’s economically favorable for our customers and reduces their costs. So, I think those incentives are very helpful. I think regulation still needs to evolve a little bit. And as to your question around pump storage, I will pass it over to Corey.

Hi Rob, I would echo Francois’ comments. I think the regulatory and incentive framework in the U.S. around mature technologies, such as wind and solar and battery storage, have set an excellent example and have created a marketplace that is robust and competitive and clear and defined about how to participate and the opportunity set for returns. And we are optimistic that the same framework can be put in place for technologies such as pumped hydro. Pumped hydro is an interesting opportunity as well because the initial capital costs are obviously much higher. The development risk is much higher. And so having a clear framework, which we can follow and have a clear view of what the outcomes will be, will be of a priority to us and will be most important to us as we continue our journey and investing in these types of assets.

Thank you very much.

Our next question comes from Robert Kwan of RBC Capital Markets. Please go ahead.

Hi, good afternoon. Just staying with the energy transition, can you just talk about your approach from a financial setup perspective? Do you think there is any changes you need to manage, both the opportunities and the risks, thinking about leverage and payout? As well you mentioned meaningful indigenous investment opportunities, a sign that came out of the KXL process. So, do you see – like what’s the role you see for indigenous investment as part of your energy transition? And the thing is that since they were looking at KXL, would you ever look at a partial monetization of Keystone to indigenous groups?

I think on the indigenous question, Robert, I will ask Bevin to respond, and then for the first part of your question, I will ask Don to take that one, please.

Sure. I will lead off, Francois. Yes, in terms of energy transition and how we view it and how that fits in the balance sheet, what we are looking here – looking at here is more of the same. So, no fundamental change of our risk preferences, long-term annuity streams, credit profile, etcetera, and returns. So, we will be quite discerning as to how we progress into that space. So, it would be evolution, not revolution, and it would look a lot like from a cash flow perspective, what we have today. We engage with the rating agencies frequently, and we will test these concepts with them. But we think the way our balance sheet is structured right now with the credit metrics we have and the credit profile that we have is where we want to be. So, we want to remain the top credit in the sector. And as we start moving into somewhat different business lines, when you actually look at the cash flow streams, they should look very similar to what you have seen for the past several decades here, so, no fundamental change there.

And Robert, this is Bevin. I’ll speak to indigenous investment with our First Nation and Tribal Nation partners and communities around our systems. We continue to look for opportunities that will benefit their communities as well as bring them in as an active partner in our developments. And potentially, as you say, associated, I guess, with our base assets in that you may have saw – seen our RFI seeking renewable power proposals for our assets in the United States. Part of our screening criteria for working with developers of those resources will have – have a score related to their capabilities around indigenous involvement. So we will continue to work with our indigenous contracting strategies across our entire TC Energy business as well as find ways to continue to support through training as well as involvement in our base businesses, our key partners. We’ve learned a lot over the last year with our partnership with Natural Law Energy. And we see it as strategic, and we believe that we can create even further strategic relationships alongside our assets with the indigenous communities that we operate in.

Thanks. If I can just finish on Keystone XL between the Alberta government and shipper reimbursements, I know you’ve done kind of the accounting entries here. But how much aggregate cash do you expect to receive over what time frame? And then are there any ongoing positive tax implications associated from having written off these assets?

Yes, Robert, it’s Don. It’s pretty much straightforward as outlined in the note there. The cash components here would be shipper recoveries of around $700 million. In the fairly near-term here, asset monetization proceeds over a measured sale process of a couple of hundred million dollars. And against that, we would see wind down costs on a cash basis probably in the neighborhood of about $0.5 billion, so net positive there. And that would probably be over a ‘21 and into ‘22 timeframe. On the tax side, we’ve reflected the tax benefits here as ordinary income rather than capital, so far more usable from our perspective and far more valuable. That would be recognized over several years, and it depends on what jurisdiction those tax losses are related to. Given the amount of capital spend we have in Canada and all the accelerated tax shelter we have here, probably a more elongated period to realize Canadian ordinary income tax benefits. In the U.S., it would be a shorter time horizon on that. I can’t give you a specific number of years, but certainly not within 2 years, but not as long as 10 years in the States.

Okay, thank you.

Our next question comes from Praneeth Satish of Wells Fargo. Please go ahead.

Good afternoon. With respect to the RFI that you announced seeking 620 megawatts of wind power, I recognize it might be early, but can you comment just so far on how the bidding process has gone? And based on what you see so far, do you think there’ll be an opportunity for TRP to invest a meaningful amount of CapEx in this build-out or do you think it will be mostly handled by third-party renewable companies?

Hi. This is Corey. It is early days, so I’m going to be measured in my response. I will tell you that to date, we sent out over 100 NDAs for folks to participate in the process, and we’ve had well over 50% response. So we feel really good about the number of respondents thus far. And we specifically asked for an RFI because our approach to this process will not be limited to simply price. It will be a combination of very specific qualifications that align with our customers’ needs with the investment criteria for TC Energy and also for the local communities that we serve. So there’ll be much more to come on this. The actual process closes – the RFI closes on May 10, on Monday. So I’m going to be a bit measured and leave that maybe to come back to you on our next earnings call.

Okay, got it. And then just switching gears a bit, I wanted to ask about Northern Border and the plan to potentially cap the heat content on the pipeline. I guess, first, if you could review the rationale for that? And then second, where does that stand today in the regulatory process? And when could the BTU limit take effect?

Yes. This is Stan. We filed second half of last year to impose a safe harbor for a certain BTU limit. And the driver there is really an operational requirement. Once you get too high of a BTU factor, it could do damage to the gas stream LDC facility. So this is all about safety and the operational integrity of our assets. Now where we’re at is the problem somewhat solved itself at least for the short-term. Flows on the Northern Border system quarter-over-quarter are down about 10%. And what we’ve seen is that, that capacity on the border system was backfilled with gas of a lower BTU quality that came in from Canada. So for the past several months, at least for the foreseeable future, there is not a BTU issue to deal with at the moment. Now to the extent that the situation changes over time and we see the BTU content creep up, we’re going to have to circle back with our customers on the producer side as well as the LDC side because, again, the issue here is we’re trying to establish a safe harbor limit that says, if you go above a certain level, then we would have the right to cut back production into the pipe given those safety and operational integrity issues.

Great. Thank you.

Our next question comes from Jeremy Tonet of JPMorgan. Please go ahead.

Hi, good afternoon.

Jeremy.

Just want to make sure you are coming through. Okay, great. I wanted to touch on Bruce Power a bit here. Given the ambitious carbon reduction goals of the Northeastern U.S. states as well as proposed transmission to bring Canadian power supply into the U.S., do you see the potential to incorporate Bruce refurbishments into creating power supply to feed into the Northeast U.S.? And could there be a transmission opportunity for TRP here? And then separately, is there a green hydrogen opportunity with Bruce Power? We’ve heard about cost savings using steam in the production process.

Corey, do you want to take that one up?

Yes. This is Corey. Sorry about that. I’m a little slow on the button. Thanks, Jeremy. As far as the transmission opportunity, I don’t know that we’re in any position to comment on the viability of that. At this stage, I’m not really aware of what steps need to be taken. I do know though on your second question that Bruce Power is a partner in the Nuclear Innovation Institute, which is actively evaluating along with the partners in the institute, items such as producing hydrogen, along with evaluating small modular reactors as a function of their business going forward. So I think there is more to come. The site is using a systematic approach to really evaluate what options are available and then how they can participate in the market.

Got it. And just to be clear on the first part, you don’t see any opportunity for Bruce refurbishments feeding supply into the Northeast U.S.?

Maybe I’ll take that one, Jeremy. It’s Francois. And just to say that when we look at the integrated resource plan for Ontario, they are calling for a net need for additional power, particularly as the Bruce and Darlington units are going through their life extension programs and even beyond then in the late ‘20s and into the early ‘30s. So given the cost profile of nuclear and its baseload nature and its emissionless nature, our view is, at least for the time being, that there’ll be a home for that load or for that supply in Ontario. And so that’s our base case assumption right now.

Got it. That makes sense. And then shifting to Mexico, just wondering if you might be able to provide some updated thoughts as far as organic growth overall potential in Mexico? And I guess, the – what do you think of the right size of your Mexican presence within your kind of portfolio overall?

Yes. This is Stan. I think in the context of the question and growth out of Mexico, the first thing we’re going to focus on is getting Villa de Reyes built and in service here by the end of the year, consistent with our prior guidance. At the same point in time, we’re still hopeful that along that same time line, we will have a revised right-of-way path to start construction again on the Tuxpan-Tula line and get that in service again 2 years or so after we start construction. Post that, I think that there is a potential need for additional demand into the southeast portion of Mexico, into the Yucatan Peninsula, and we are somewhat uniquely situated to potentially serve that via an extension of our Sur de Texas pipeline as well as on the West Coast, the potential for West Coast Mexican LNG exports, probably on a little bit longer time line, however. So when I look at the investment opportunity, fits and starts, bite sizes, another couple of hundred million dollars a year over the next several years doesn’t seem out of line.

Got it. That’s helpful. Thanks.

Our next question comes from Michael Lapides of Goldman Sachs. Please go ahead.

Hey, guys. Thank you for taking my question. Actually, I have a couple of them. First, can you – is there a way to quantify for Coastal GasLink and maybe for the MCR Unit 6 at Bruce? What the potential cost inflation maybe whether it was due to permitting issues and other at Coastal GasLink or whether it was due to COVID at Bruce 6, just kind of how material dollar wise are these?

I can start that on Coastal GasLink. It’s Tracy here. We’re just, as you know, we are coming out of – in the process of coming out of a construction shutdown largely due to spring breakup. And previous to that, the Northern Health in – order in – there is a Northern Health order coming out of British Columbia that really reduced the workforce that was in the northern – the major capital projects up there for a period of time, January kind of through to March, April. So that’s all had us, put us in a position. It’s important to us that we can start construction. It’s important to us that we do that in a safe manner. So we’ve implemented some very strict protocols for COVID, in conjunction with Northern Health, and we’ve now bought clearance to fully remobilize coming out of spring breakup. So, all of that has necessitated us to take another look at the plan, how we optimize construction. As we go forward, we’re in the midst of doing that with LNG Canada to make sure that we need all of their requirements on schedule and we mitigate whatever cost we can falling from that. So it’s early to say on where that will all fall out, but we are in the midst of it now, Michael.

Got it. And on Bruce 6?

Hi, Michael, it’s Corey. Bruce 6 is on schedule and on budget.

Got it. And then can you remind me your results at the liquids business, really Keystone, Marketlink, etcetera, highlighted both a little bit of volumetric as well as pricing differential. Can you just remind me how contracted is Keystone? How contracted is Marketlink? And are those take-or-pay contracts or throughput dependent?

Yes. Thank you, Michael. This is Bevin. Our systems are under strong, strong utilization, particularly ex Hardisty on our base Keystone asset out of Western Canada. It’s been fully utilized, and we actually had our highest utilization through Q1 that we’ve had in its history and in terms of its operational performance as well. With respect to – and of all those volumes, so we’re required to leave a certain percentage for spot volumes. But otherwise, we were fully contracted, take-or-pay, on the Keystone base system. When it comes to our Marketlink asset that was created as a pre-build for Keystone XL and we contracted that again under a take-or-pay nature with a number of parties. But that contract profile, we struck contracts on a much shorter tenure in order to ensure that they would kind of wind off by the time we would get to an in-service date of the XL asset. Given that we’re not advancing XL, we’re looking to re-contract and reuse that spare capacity that we do have on Marketlink. Currently, we’re – on our Marketlink asset, we’re effectively about, let’s hold on here one second, I think it’s 45 – yes, our U.S. Gulf Coast system is about 45% contracted. That’s lower compared to last year when we would have been in that 62%, but that reduction is reflected of some contracts rolling off. With that Gulf Coast and Marketlink system, they fundamentally are driven by the differential between Cushing and the Gulf Coast. And as a result of the pandemic and reduced demand and increased supplies globally on the water, we’ve seen those that arb between Cushing and the Gulf Coast weaken. And as such, we’ve been making up revenue utilizing our marketing affiliate by moving more barrels through that system, albeit at a lower margin than what our historical tolls would have been. But we’ve been able to optimize that asset effectively utilizing our marketing affiliate.

Got it. And the remaining 45% of Marketlink that’s contracted, when do those contracts roll off?

Well, they are staggered, Michael. I’m not going to roll out. They are all on a confidential basis with those customers, but you could appreciate that those would trend. Our in-service date was intended to be in 2023. So you can anticipate that the vast majority of those contracts, legacy contracts, would be rolling off at that period of time, but we’re well in hand on backfilling and finding re-contracting opportunities in this environment now that our path forward is clear.

Got it. Thank you, guys. Much appreciated. Go have a good weekend.

There are currently no further questions in the queue. We do have time for more questions should you have any. [Operator Instructions] Ladies and gentlemen, this concludes the question-and-answer session. If there are any further questions, please contact Investor Relations at TC Energy. I will now turn the call over to Francois Poirier. Please go ahead.

Thanks very much, and thanks for all of you who joined us this afternoon. I know this is a busy day with a number of companies in your coverage universe announcing results. So I appreciate your interest. And in closing, I’d like to leave you with the following key messages. Looking forward, I expect our assets will continue to provide an essential service to the functioning of the North American economy and that the demand for our services will remain strong for decades to come. As we advance our $20 billion secured program and various other organic growth opportunities, we expect to build on our long-term track record of growing earnings, cash flow and dividends per share. With an irreplaceable asset footprint, extensive technical expertise, our strong financial position and a commitment to innovation, we have the right ingredients to prosper irrespective of the pace or direction of energy transition. Looking forward, we will be deliberate and disciplined in every investment decision we make. We will also continue to focus on safety, sustainability, working according to our values and responding quickly to market signals and signposts to ensure we remain a leading North American energy infrastructure company today and in the future. So that concludes my closing remarks. Thanks very much for joining us today and we appreciate your ongoing interest and support and look forward to talking to you again soon.

This concludes today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day.